The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
The technical field generally relates to utilizing divalent brines in viscosified well treatment fluids.
Many wellbore treatment applications are treatment pressure-limited. The treatment pressure is affected, for example, by the pumping rate required to perform a treatment, by the downhole pressure that must be achieved during the treatment, by the distance through the treatment string from the treating equipment to the formation to be treated, by the viscosity of the fluid being pumped, and by the available diameter of the treatment string. Currently available methods to reduce the treating pressure or to treat at higher pressures are either limited or significantly increase costs. Examples of activities to reduce the treating pressure include reducing pump rates which may reduce the economic value of the treatment, increasing the treatment string diameter which requires higher cost tubing and/or a larger wellbore diameter, and reducing the viscosity of the fluid to be pumped which may result in risk of treatment failure or a treatment with reduced economic value. Treating at higher pressures increases the cost of the treatment and increases the risk of equipment failure and therefore unsuccessful treatment. Treating at non-standard pressures (e.g. above 10,000 psi) requires the utilization of special equipment that increases costs and which may not be readily available, and treatments cannot exceed the limit of available equipment which is presently about 15,000 psi in many areas.
Treatment pressures can also be reduced by utilizing a treatment fluid having a higher density. The hydrostatic head of a denser fluid allows a given bottom-hole pressure to be achieved at a lower surface pressure. It is known to utilize a sodium bromide (NaBr) brine, for example, to achieve a fluid having a higher density. However, presently available heavy brines are expensive and not available in all locations. Some divalent brines, for example calcium chloride (CaCl2), are cheap and readily available, and other divalent brines, for example zinc bromide (ZnBr2), allow very high density fluids to be generated. For example, while an NaBr brine can have a density of around 12.5 pounds per gallon (ppg), a CaBr2 brine can have a density of around 14.2 ppg, and a ZnBr2 brine can have a density around 19.2 ppg.
Presently available technologies do not provide for efficient hydration of polymers in divalent brines, limiting the applications of these brines as treatment fluids. Further, borate crosslinkers do not function well in divalent brines at moderate temperatures and high pH, or in general at high temperatures. Zirconium crosslinkers work well in divalent brines and at high temperatures, but unlike borate crosslinkers, zirconium crosslinkers suffer irreversible shear degradation rendering them undesirable, as presently available, for deep wells and/or for high rate applications. Certain embodiments may use viscosifying techniques similar with those disclosed in pending U.S. application Ser. Nos. 12/116,730 and 12/116,759, the disclosures of which are incorporated herein in their entirety. For the reasons described, further technological developments are desirable in this area.